KR102684301B1 - Improved sulfur recovery operations with improved carbon dioxide recovery - Google Patents

Abstract

A process for recovering sulfur and carbon dioxide from a sour gas stream, the process comprising: providing a sour gas stream to a membrane separation unit, the sour gas stream comprising hydrogen sulfide and carbon dioxide; separating hydrogen sulfide from carbon dioxide in the membrane separation unit to obtain a retentate stream and a first permeate stream, wherein the retentate stream comprises hydrogen sulfide and wherein the permeate stream comprises carbon dioxide. Contains; processing the concentrate stream in a sulfur recovery unit to produce a sulfur stream and a tail gas stream, wherein the sulfur stream comprises liquid sulfur; introducing the permeate stream to an amine absorption unit; and processing the permeate stream in an amine absorption unit to produce a concentrated carbon dioxide stream.

Description

Improved sulfur recovery operations with improved carbon dioxide recovery

The described systems and methods relate to improving hydrogen sulfide and carbon dioxide recovery. More specifically, provided are systems and methods for combined amine absorption and membrane gas separation technology.

Acid gas streams with low concentrations of hydrogen sulfide, such as concentrations below 30 mol%, can cause problems in Claus units. Low concentrations of hydrogen sulfide can result in low temperatures in the Claus furnace. At these low temperatures, contaminants such as BTX, mercaptans, and C ₂ + hydrocarbons cannot be destroyed. Contaminants that are not destroyed can cause catalyst deactivation in other parts of the Claus unit.

Selective amine absorption techniques can be used to increase the hydrogen sulfide concentration of Claus plant feeds, but these processes tend to require large, expensive columns with limited results in increasing the hydrogen sulfide concentration.

The described systems and methods relate to improving hydrogen sulfide and carbon dioxide recovery. More specifically, provided are systems and methods for combined amine absorption and membrane gas separation technology.

In a first aspect, a process for recovering sulfur and carbon dioxide from a sour gas stream is provided. The process includes: providing a sour gas stream to a membrane separation unit, the sour gas stream comprising hydrogen sulfide and carbon dioxide; separating hydrogen sulfide from carbon dioxide in the membrane separation unit to obtain a retentate stream and a first permeate stream, wherein the retentate stream comprises hydrogen sulfide and wherein the permeate stream comprises carbon dioxide. Contains; introducing the concentrate stream into a sulfur recovery unit; processing the concentrate stream in a sulfur recovery unit to produce a sulfur stream and a tail gas stream, wherein the sulfur stream comprises liquid sulfur; introducing the permeate stream to an amine absorption unit; and processing the permeate stream in an amine absorption unit to produce a concentrated carbon dioxide stream.

According to at least one embodiment, the concentrate stream may have a concentration of hydrogen sulfide of 80 to 95 mol%. The membrane separation step involves a carbon dioxide-selective membrane. The membrane separation unit includes a membrane, wherein the membrane can have a carbon dioxide-hydrogen sulfide selectivity of at least 10 and a permeance of at least 500 gas permeation units (gpu). The membrane can be made from perfluoropolymer.

According to at least one embodiment, the membrane separation unit comprises two membrane stages in a retentate-in-series configuration. According to at least another embodiment, the membrane separation unit comprises two membrane stages in a permeate-in-series configuration.

In a second aspect, a process for recovering sulfur and carbon dioxide from a sour gas stream is provided. The process includes: providing a sour gas stream to a selective amine absorption unit, the sour gas stream comprising hydrogen sulfide and carbon dioxide; separating hydrogen sulfide from carbon dioxide in a selective amine absorption unit to produce a concentrated carbon dioxide stream and a concentrated hydrogen sulfide stream, wherein the enriched carbon dioxide stream comprises carbon dioxide; introducing the concentrated hydrogen sulfide stream into a membrane separation unit, wherein the concentrated hydrogen sulfide stream comprises hydrogen sulfide and carbon dioxide; separating hydrogen sulfide from carbon dioxide in the concentrated hydrogen sulfide stream in the membrane separation unit to produce a retentate stream and a permeate stream; introducing the concentrate stream into a sulfur recovery unit, wherein the concentrate stream comprises hydrogen sulfide; and processing the concentrate stream in a sulfur recovery unit to produce a sulfur stream and a tail gas stream, wherein the sulfur stream comprises liquid sulfur.

According to at least one embodiment, the hydrogen sulfide concentration in the concentrate stream may be 80 to 95 mol%. The membrane separation step involves a carbon dioxide-selective membrane. The membrane separation unit includes a membrane, wherein the membrane has a carbon dioxide-hydrogen sulfide selectivity of at least 10 and a permeability of at least 500 gpu.

According to at least one embodiment, the membrane separation unit comprises a membrane made from a perfluoropolymer. According to at least another embodiment, the tail gas stream is recycled to the selective amine absorption unit.

According to at least one embodiment, the membrane separation unit comprises two membrane stages in a retentate-continuous arrangement. According to at least another embodiment, the membrane separation unit comprises two membrane stages in a permeate-continuous arrangement.

In a third aspect, a first sour gas stream having a carbon dioxide and hydrogen sulfide concentration greater than 10 mol% and a nitrogen concentration less than 10 mol% and a first sour gas stream having a carbon dioxide and hydrogen sulfide concentration less than 20 mol% or a nitrogen concentration greater than 10 mol%. A process is provided for recovering sulfur and carbon dioxide from two sour gas streams. The process includes: introducing a first sour gas stream into a membrane separation unit and separating the first sour gas stream to obtain a retentate stream and a permeate stream, the retentate stream comprising hydrogen sulfide and the permeate stream comprising carbon dioxide. Includes; Introducing the permeate stream and the second sour gas stream to a selective amine absorption unit and using the amine absorption process to obtain a recovered hydrogen sulfide stream and a concentrated carbon dioxide stream, the recovered hydrogen sulfide stream comprising hydrogen sulfide and a concentrated carbon dioxide stream. The carbon dioxide stream includes carbon dioxide; recycling the recovered hydrogen sulfide stream to a membrane separation unit; and introducing the concentrate stream into a sulfur recovery unit and processing the concentrate stream using a Claus process to obtain a sulfur stream comprising sulfur.

According to at least one embodiment, the concentrate stream entering the sulfur recovery unit comprises 80 to 95 mol% hydrogen sulfide. According to at least one embodiment, the membrane separation unit comprises two membrane stages in a retentate-continuous arrangement. According to at least another embodiment, the membrane separation unit comprises two membrane stages in a permeate-continuous arrangement.

The membrane separation unit may include a membrane made of perfluoropolymer. According to at least one embodiment, the membrane separation unit comprises a membrane having a carbon dioxide-hydrogen sulfide selectivity of at least 10 and a permeability of at least 500 gpu. According to at least one embodiment, the second sour gas stream comprises 5 to 50 mol% nitrogen.

These and other features, aspects and advantages of the present embodiments will be better understood in conjunction with the following description, claims and accompanying drawings. However, it should be noted that the drawings illustrate only a few embodiments and therefore should not be considered limiting in scope as other equally effective embodiments may be permissible.
Figure 1 is a plot of carbon dioxide-hydrogen sulfide selectivity and carbon dioxide permeability for various membrane materials.
Figure 2 is an illustration of various membrane stage arrangements of a membrane separation unit.
3 is an illustration of various process and system arrangements for recovering sulfur and carbon dioxide from sour gas streams.
Figure 4 is a plot of hydrogen sulfide concentration in hydrogen sulfide-enriched acid gas as a function of hydrogen sulfide in the feed gas for a selective amine absorption unit.
Figure 5 is an illustration of an embodiment of the process and system using a two-stage retentate-continuous membrane stage arrangement where sour gas is fed to the membrane separation unit.
Figure 6 is an illustration of an embodiment of the process and system using a two-stage permeate-continuous membrane stage arrangement in which sour gas is fed to a membrane separation unit and a selective amine absorption unit.
Figure 7 is an illustration and comparison of two processes for recovering sulfur and carbon dioxide from a sour gas stream, one with a membrane separation step and the other without a membrane separation step.
8 is an illustration of an embodiment of a process and system using a two-stage retentate-continuous membrane stage arrangement and a selective amine absorption unit to recover sulfur and carbon dioxide from a sour gas stream.
9 is an illustration of an embodiment of a process and system using a two-stage permeate-continuous membrane stage arrangement with a selective amine absorption unit to recover sulfur and carbon dioxide from a sour gas stream.

Although several embodiments will be described, those skilled in the art will understand that many examples, modifications and variations of the devices and methods described herein are within the scope and spirit of the present embodiments. Accordingly, the exemplary embodiments described herein are described without loss of generality and without imposing limitations on the claimed embodiments.

Embodiments described herein relate to hybrid processes and systems containing both an amine absorption process and a membrane separation unit to produce a concentrated hydrogen sulfide gas stream and a concentrated carbon dioxide gas stream. Advantageously, the hybrid process results in an overall sulfur recovery process with improved efficiency and economy compared to conventional processes. Advantageously, the processes and systems described herein can remove carbon dioxide resulting in a concentrated hydrogen sulfide stream for the sulfur recovery unit, which can reduce the amount of carbon dioxide in the tail gas treatment process of the Claus plant, and can reduce the amount of carbon dioxide in the tail gas treatment process of the Claus plant. Reduces the complexity and cost of operating gas treatment processes. Advantageously, the combination of a membrane separation unit and an amine absorption process can reduce or eliminate the accumulation of carbon dioxide due to recycle gas in the Claus plant when the Claus plant feed has high concentrations of carbon dioxide. Advantageously, the combination of a membrane separation unit and an amine absorption process can eliminate the use of an absorption process in tail gas treatment resulting in improved sulfur recovery and reduced capital expenditure. Advantageously, the combination of a membrane separation unit and an amine absorption process results in increased recovery of carbon dioxide for use in improved oil recovery operations and more efficient sequestration of carbon dioxide compared to the use of the amine absorption process alone. Advantageously, removal of contaminants from the feed to the amine absorption process can reduce or eliminate foaming and other operational problems in the amine absorption process. Advantageously, the membrane separation unit and amine absorption process improve Claus unit operability and efficiency resulting in improved sulfur recovery and minimized sulfur dioxide emissions from the incinerator stack. Advantageously, removing carbon dioxide through a combination of a membrane separation unit and an amine absorption process results in improved efficiency and increased destruction of contaminants in the furnace of the Claus unit.

As used herein, “total recovery of sulfur” or “sulfur recovery” refers to the percent reduced sulfur based on the amount of sulfur present in the acid gas feed stream. Recovery of 99.0% means that 99.0% of the sulfur in the acid gas feed stream is recovered as part of the recovered sulfur stream.

As used herein, “permeate” as a verb means to spread, flow, or pass through the membrane of a membrane unit. For example, liquids and gases can permeate the membrane. As a noun, permeate refers to liquids and gases that have passed through the membrane of a membrane unit.

Membrane separation productivity is described by the flux or volumetric flow of permeate through the membrane (unit of volume per area per time). The permeability of a membrane refers to the flux sensitivity to the average difference in pressure across the membrane (or transmembrane pressure). A useful measure of the separating power of a membrane is its selectivity (a _ij ), which is the ratio of the relative concentrations of components i and j in the permeate stream to the components in the feed stream. By convention, the component that passes more through the membrane is designated component i such that the selectivity coefficient exceeds 1. The selectivity of the membrane can be determined using the diffusion coefficients, D _i and D _j , and the gas adsorption coefficients, K _i and K _j , for each component as shown in Equation 1.

Equation 1

The ratio of diffusion coefficients for two components is referred to as mobility selectivity, and the ratio of adsorption coefficients is referred to as adsorption selectivity. For polymer membranes, smaller molecules generally diffuse more easily than larger molecules, resulting in larger diffusion coefficients. On the other hand, smaller molecules generally result in smaller adsorption coefficients because they are less condensable than larger molecules. When the two components to be separated are hydrogen sulfide and carbon dioxide, the mobility selectivity favors carbon dioxide (dynamic diameter of 3.3 Å) over hydrogen sulfide (dynamic diameter of 3.6 Å), and the adsorption selectivity favors hydrogen sulfide over carbon dioxide.

In general, the adsorption selectivity term dominates the mobility selectivity term for hydrogen sulfide-selective membranes, and vice versa for carbon dioxide-selective membranes. Examples of types of hydrogen sulfide-selective membranes include rubbery polar membranes. Examples of carbon dioxide-selective membranes include glassy hydrophobic polymers. Figure 1 shows log plots of permeability and selectivity for various materials. The plot shows that the perfluorinated series of polymers has suitable carbon dioxide/hydrogen sulfide selectivity combined with suitable carbon dioxide permeability. Membranes made from these materials are particularly suitable for use in the processes described in this disclosure.

In some embodiments, the membrane can have a carbon dioxide/hydrogen sulfide selectivity of at least 10 and a carbon dioxide permeability of at least 500 gpu. In some cases, membranes with a carbon dioxide/hydrogen sulfide selectivity of 20 are used. In some cases, membranes with a carbon dioxide/hydrogen sulfide selectivity of 30 are used. In some cases, the membrane may have a carbon dioxide/hydrogen sulfide selectivity of about 10 to 30.

The membrane stage may comprise one or multiple membrane modules in various arrangements. For example, various membrane stage arrangements are shown in Figure 2; A single-pass membrane arrangement is shown in Figure 2a; A permeate-continuous two-stage arrangement is shown in Figure 2b; The concentrate sequential two-stage arrangement is shown in Figure 2c.

Figure 2a is the simplest arrangement with a single membrane stage. 2A, feed-gas stream 201 is compressed in a first compressor 205 to obtain compressed feed-gas stream 208. The compressed feed-gas stream 208 is fed to a single-pass membrane stage 210 where it is passed to a carbon dioxide-selective membrane to obtain a single-pass retentate stream 211 and a single-pass permeate stream 212. introduced; The single-pass concentrate stream 211 and single-pass permeate stream 212 are rich in hydrogen sulfide and carbon dioxide, respectively.

Figure 2b includes two membrane stages where the permeate from the first stage is fed to the next stage. In Figure 2b, feed-gas stream 201 is compressed in a first compressor 205 to obtain compressed feed-gas stream 208. The compressed feed-gas stream 208 is combined with a second permeate-continuous retentate stream 231 from the second permeate-continuous membrane stage 230 to obtain a first-stage feed-gas stream 209. are combined. The first-stage feed-gas stream 209 is introduced into a first permeate-continuous membrane stage 220, wherein a first permeate-continuous retentate stream 221 and a first permeate-continuous permeate stream (22) is separated using a carbon dioxide-selective membrane to obtain; The first permeate-continuous retentate stream 221 and first permeate-continuous permeate stream 222 are rich in hydrogen sulfide and carbon dioxide, respectively. The first permeate-continuous permeate stream 222 is compressed in a second compressor 225 and then introduced into a permeate-continuous membrane stage 230, wherein the second permeate-continuous permeate stream 231 and a second permeate - separated using a carbon dioxide-selective membrane to obtain a continuous permeate stream (232); The second permeate-continuous retentate stream 231 and the second permeate-continuous permeate stream 232 are rich in hydrogen sulfide and carbon dioxide, respectively. Second permeate-continuous permeate stream 231 is then combined with compressed feed-gas stream 208.

Figure 2c includes two membrane stages where the concentrate from the first stage is fed to the next stage. 2C, the feed-gas stream 201 is compressed in a first compressor 205 to obtain a compressed feed-gas stream 208, which is divided into a first retentate-continuous permeate stream 241 and a second is fed to a first concentrate-continuous membrane stage (240) where it is separated using a carbon dioxide-selective membrane to obtain a concentrate-continuous concentrate stream (242); The first retentate-continuous permeate stream 241 and the first retentate-continuous retentate stream 242 are rich in carbon dioxide and hydrogen sulfide, respectively. The first retentate-continuous retentate stream 242 is then introduced into a second retentate-continuous membrane stage 250, wherein the second retentate-continuous permeate stream 251 and the second retentate-continuous retentate are combined. separated using a carbon dioxide-selective membrane to obtain a water stream (252); The second retentate-continuous permeate stream 251 and the second retentate-continuous retentate stream 252 are rich in carbon dioxide and hydrogen sulfide, respectively. The second retentate-continuous permeate stream 251 is combined with the feed-gas stream 201 and recycled through the process.

To illustrate various configurations, an example was simulated using the three configurations shown in Figure 2 with feed gases containing 10 vol% hydrogen sulfide and 90 vol% carbon dioxide. The membrane module was assumed to have sufficient membrane to produce concentrated sour gas containing 90 vol% hydrogen sulfide. The membrane is assumed to have a carbon dioxide permeability of 500 gpu, a hydrogen sulfide permeability of 50 gpu, and a nitrogen permeability of 20 gpu. These parameters typically result in a carbon dioxide-hydrogen sulfide selectivity of about 10, and a carbon dioxide-nitrogen selectivity of about 25.

Simulations suggested that the single-pass membrane arrangement required the least membrane area and compression force, but also recovered the lowest amount of hydrogen sulfide from the feed gas (53% of hydrogen sulfide recovered from the feed gas; Table 1). The two-stage arrangement with permeate continuation recovered the most hydrogen sulfide from the feed gas, but required significantly larger membrane areas and theoretical compressor power (Table 2). The two-stage retentate-continuous arrangement resulted in hydrogen sulfide recovery intermediate between the single-pass membrane arrangement and the two-stage permeate-continuous arrangement, with intermediate membrane area and theoretical compressor power (Table 3). The arrangement may vary depending on available resources and desired results.

Stream composition: single-pass membrane arrangement ^* enter
(bar) ^b H ₂ S (mol%) _CO2
(mol%) flux
(mmscfd) Feed-gas stream (201) 10.0 10.0 90.0 1.0 Single-Pass Concentrate Stream (211) 10.0 90.0 10.0 0.059 Single-pass permeate stream (212) 1.0 5.0 95.0 0.941 ^a* Using a membrane area of 132 m ² and a theoretical compressor power of 116 kWe.
^b absolute pressure

Stream composition: two-stage permeate-continuous arrangement ^a enter
(bar) ^b _H2S
(mol%) _CO2
(mol%) flux
(mmscfd) Feed-gas stream (201) 1.0 10.0 90.0 1.0 First-stage feed-gas stream (209) 10.0 10.0 90.0 1.74 First PIS concentrate stream (221) 10.0 90.0 10.0 0.103 First PIS continuous permeate stream (222) 1.0 5.0 95.0 1.63 Second PIS concentrate stream (231) 10.0 10.0 90.0 0.74 Second PIS permeate stream (232) 1.0 0.81 99.2 0.90 PIS, permeate-in-series
^a Cumulative area of 227 in the first PIS membrane stage 220; and using theoretical compressor powers of 112 kWe and 231 kWe to power the first and second compressors 205 and 225, respectively.
^b absolute pressure

Stream Composition: Two-Stage Concentrate-Continuous (RIS) Configuration ^a enter
(bar) ^b _H2S
(mol%) _CO2
(mol%) Flow rate (mmscfd) Feed-gas stream (201) 1.0 10.0 90.0 1.00 Compressed Feed-Gas Stream (208) 10.0 10.6 89.5 1.44 First RIS concentrate stream (242) 10.0 25.0 75.0 0.53 First RIS permeate stream (241) 1.0 2.05 98.0 0.91 Second RIS concentrate stream (252) 10.0 90.0 10.0 0.09 Second RIS permeate stream (251) 1.0 11.7 86.3 0.44 RIS, retentate-in-series
^a Membrane areas of 105 and 88 m ² in the first and second RIS membrane stages 240 and 250, respectively; and with a theoretical compressor power of 165 kWe.
^b absolute pressure

Figure 3 is an illustration of several processes for separating sour gas streams, each process having the sour gas introduced at a different location. Referring to Figure 3A, first sour gas stream 301 is introduced into compressor 305, where it is compressed to obtain compressed sour gas stream 309. The compressed sour gas stream 309 is then introduced into a membrane separation unit 310. The first sour gas stream 301 may originate from any source that produces a gas stream containing acid gas. The first sour gas stream 301 may include acid gases and contaminants. Acid gases in the first sour gas stream 301 may include hydrogen sulfide, carbon dioxide, and combinations thereof. Contaminants in sour gas stream 301 may include BTX, carbonyl sulfide (COS), carbon disulfide (CS ₂ ), thiol (R-SH), water, and combinations thereof. BTX may include benzene, toluene, xylene, and combinations thereof. In at least one embodiment, first sour gas stream 301 contains hydrogen sulfide, carbon dioxide, BTX, COS, CS ₂ , R-SH, water, and combinations thereof. The amount of hydrogen sulfide in the first sour gas stream 301 is 20 mol% to 55 mol%, alternatively 20 mol% to 50 mol%, and alternatively 20 mol% to 25 mol%. In at least one embodiment, the amount of hydrogen sulfide in the first sour gas stream 301 is 20 mol% to 25 mol%.

Membrane separation unit 310 may separate hydrogen sulfide from carbon dioxide in compressed sour gas stream 309 to obtain a hydrogen sulfide-enriched concentrate stream 311 and a carbon dioxide-enriched permeate stream 312. Membrane separation unit 310 may include a membrane module having a membrane. The membrane within membrane separation unit 310 may be any type of membrane capable of separating hydrogen sulfide and carbon dioxide. In at least one embodiment, the membrane is a carbon dioxide-selective membrane. According to at least one embodiment, the membrane may be made of a polymer selected from the family of perfluorinated polymers. Although membrane separation unit 310 is illustrated using a single unit, the separation unit may include multiple membrane modules and membrane stages in various arrangements. According to at least one embodiment, the membrane separation unit has three arrangements as shown in Figure 2; That is, it may include any of a single-pass arrangement, a two-stage permeate-continuous arrangement, or a two-stage retentate-continuous arrangement. Those skilled in the art will also consider other suitable arrangements.

Hydrogen sulfide-enriched concentrate stream 311 may contain hydrogen sulfide and contaminants. Contaminants in hydrogen sulfide-enriched concentrate stream 311 may include BTX, COS, CS ₂ , R-SH, water, and combinations thereof. In at least one embodiment, the hydrogen sulfide concentration in hydrogen sulfide-enriched concentrate stream 311 is 80 mol% to 95 mol%; For example, it may be about 90 to 95 mol%. Advantageously, hydrogen sulfide concentrations within this range may be suitable to achieve a temperature profile in the furnace of a Claus unit suitable for destroying contaminants. Hydrogen sulfide-rich concentrate stream 311 may be introduced into sulfur recovery unit 320.

Carbon dioxide-enriched permeate stream 312 may contain carbon dioxide, inert gases, and combinations thereof. Carbon dioxide-enriched permeate stream 312 may be introduced into amine absorption unit 330.

Sulfur recovery unit 320 may be any type of system capable of recovering sulfur from hydrogen sulfide and other sulfur-containing contaminants. In at least one embodiment, sulfur recovery unit 320 may be a Claus unit. Sulfur recovery unit 320 may produce a sulfur stream 322 and a tail gas stream 321. Sulfur stream 322 may contain liquid sulfur. Typically, the sulfur recovery unit 320 requires that the gas supplied to the unit contain at least 20 vol% hydrogen sulfide. According to at least one embodiment, the hydrogen sulfide-enriched concentrate stream 311 contains at least 20 mol% hydrogen sulfide, preferably at least 60 mol% hydrogen sulfide, more preferably at least 80 mol% hydrogen sulfide, and even more. Preferably it contains at least 90 mol% hydrogen sulfide. According to at least one embodiment, the hydrogen sulfide-enriched concentrate stream 311 contains about 80 to 95 mol % hydrogen sulfide, preferably about 85 to 95 mol % hydrogen sulfide, more preferably about 90 to 95 mol % hydrogen sulfide. Contains

Claus units are commonly used to recover sulfur from sour gas. Because they generally operate at relatively low pressures (i.e. below about 1 bar gauge), Claus units in conventional systems often require larger and more expensive equipment to process sour gas. And even after treating the sour gas, about 1 to 2 mol% of the original sulfur may remain in the tail gas. Tail gases from modern Claus units require additional treatment to remove residual sulfur from the tail gases so that they can be safely discharged to the atmosphere. An example of a common tail gas treatment process is the shell off-gas treatment process (SCOT). According to some embodiments, the process may be performed such that the tail gas stream 321 does not contain significant amounts of sulfur such that tail gas treatment other than oxidation is not required. According to at least one embodiment, the process, system, or both are free of tail gas treatment units and processes (other than simple thermal oxidation). According to at least one embodiment, the process can be performed without a subsequent tail gas treatment step involving amine absorption. According to at least one embodiment, the system may be without a tail gas treatment unit arranged to treat the tail gas using amine absorption.

Amine absorption unit 330 may be any system capable of recovering carbon dioxide using amine absorption. Although the amine absorption unit is shown as a single column, it should be understood that the amine absorption unit 330 may include a variety of configurations. For example, one of ordinary skill in the art would consider using one or more absorption columns in various arrangements, one or more stripping columns, other gas-liquid contacting equipment, or combinations thereof. Amine absorption unit 330 may produce a treated carbon dioxide stream 331 and a recovered hydrogen sulfide stream 332. According to at least one embodiment, the recovered hydrogen sulfide stream 332 has about 10 mol% to about 70 mol%, preferably about 30 to 70 mol%, more preferably about 40 to 70 mol%, and even more preferably Typically, it may have a hydrogen sulfide concentration ranging from about 50 to 70 mol%. Treated carbon dioxide stream 331 may be introduced into a process for carbon dioxide sequestration or used in an enhanced oil recovery process. Advantageously, having a membrane separation step 310 upstream of the amine absorption unit 330 may allow the use of smaller, less expensive equipment within the amine absorption unit 330. According to at least one embodiment, at least a portion of the recovered hydrogen sulfide stream 332 may be removed from the process in a bleed stream 333.

3B and 3C illustrate that FIGS. 3B and 3C include a second sour gas stream 302 introduced after the membrane separation unit 310 and combined with the carbon dioxide-enriched permeate stream 312; and FIG. 3B does not include the first sour gas stream 301, and the recovered hydrogen sulfide stream 332 is recycled through the process and system without being combined with any other feed streams. According to at least one embodiment, the process and system may include introducing the second sour gas stream 302 directly into the amine absorption unit 330.

The most suitable arrangement will depend on a variety of factors, but especially the composition of the available gas stream(s). If the sour gas stream contains a significant amount of nitrogen (i.e., greater than about 10 mol%), or if the sour gas contains less than about 20 mol% hydrogen sulfide, it is generally advantageous to introduce the nitrogen-containing stream into the amine absorption unit. do. For example, if sour gas containing significant amounts of nitrogen is introduced into the membrane separation step 310, the nitrogen may be retained in the retentate, resulting in somewhat diluted hydrogen sulfide and retentate. On the other hand, introducing nitrogen-containing sour gas into the amine absorption unit causes nitrogen to be removed along with the treated carbon dioxide stream 331.

The amine absorption process is also suitable for treating sour gas containing less than about 20 mol% hydrogen sulfide. Figure 4 shows a plot of hydrogen sulfide concentration in hydrogen sulfide-enriched gas recovered from a selective amine absorption process as a function of hydrogen sulfide concentration in the feed gas to the process. As shown in Figure 4, the amine absorption process is most effective in treating feed gases with relatively low concentrations of hydrogen sulfide (i.e., less than about 20 mol%). Additionally, the operational cost of stripping dissolved hydrogen sulfide from the solvent in the amine absorption process is generally lower than when the amount of hydrogen sulfide in the feed gas is relatively low.

Example

The following examples are included to demonstrate embodiments of the present disclosure and should be considered non-limiting. Certain embodiments represent techniques, systems, compositions, and devices that have been found to function well in the practice of the present disclosure and, therefore, can be considered to constitute modes for its practice. Changes may be made to the embodiments disclosed in the Examples without departing from the spirit and scope of the disclosure.

Example 1: Two-stage retentate-continuous arrangement with feed to membrane separation unit and amine absorption unit

Simulations were performed using a two-stage retentate-continuous membrane stage arrangement with sour gas fed to the membrane separation unit. An example of the process and system is shown in Figure 5. The process and system shown in Figure 5 includes similar elements and features to those illustrated in Figures 2C and 3C. In Figure 5, sour natural gas stream 501 is provided having carbon dioxide, hydrogen sulfide, and natural gas. Sour natural gas stream 501 may also contain contaminants such as BTX, carbonyl sulfide (COS), carbon disulfide (CS ₂ ), thiols, water, and the like. Sour natural gas stream 501 is processed in natural gas processing unit 510 by a non-selective acid gas removal process to obtain sweetened natural gas stream 502 and sour gas stream 503. Sour gas stream 503 contains 90 mol% carbon dioxide, 10 mol% hydrogen sulfide, and negligible amounts of contaminants. The composition of the sour gas stream 503 as it leaves the natural gas processing unit 510 is not suitable for processing in a conventional Claus unit because the concentration of hydrogen sulfide in the stream is not sufficient to carry out the thermal steps of the Claus process. Because it doesn't.

Sour gas stream 503 may be combined with other streams containing hydrogen sulfide. In this case, the sour gas stream 503 is combined with the second membrane stage permeate stream 532 and the recovered hydrogen sulfide stream 552 and then compressed using a compressor to obtain a compressed mixed stream 506. The compressed mixed stream is introduced into the first membrane stage (520) where it is separated to obtain a first membrane stage retentate stream (521) and a first membrane stage permeate stream (522). The first membrane stage retentate stream is then introduced into a second membrane stage 530 to obtain a second membrane stage retentate stream 531 and a second membrane stage permeate stream 532.

The first and second membrane stages 520, 530 have carbon dioxide-selective membranes with a carbon dioxide permeability of about 500 gpu and a carbon dioxide-hydrogen sulfide selectivity of about 10. The hydrogen sulfide and carbon dioxide concentrations of the second membrane stage retentate stream 531 are 90 mol% and 10 mol%, respectively (Table 4). The hydrogen sulphide concentration in this stream is suitable for treatment in the Claus unit. The second membrane stage retentate stream 531 is then introduced to a sulfur recovery unit 540 where it is processed using the Claus process to obtain a sulfur stream 542 and a tail gas stream 541. Because a substantial amount of carbon dioxide is removed by the first and second membrane stages 520, 530, tail gas stream 541 has a significantly reduced flow rate compared to a similar tail gas from a conventional process.

Tail gas stream 541 may be combined with sour gas stream 503 or first membrane stage permeate stream 522. In this case, the tail gas stream 541 is passed through the first membrane before being introduced into the selective amine absorption unit 550 where it is processed using an amine absorption process to obtain a concentrated carbon dioxide stream 551 and a recovered hydrogen sulfide stream 552. It is combined with stage permeate stream 522. The recovered hydrogen sulfide stream 552 is combined with the sour gas stream 503 so that it can be recycled through the process and system.

Stream composition: two-stage retentate-continuous membrane stage arrangement with feed gas fed to membrane separation unit and selective amine absorption unit ^* enter
(bar) ^b _H2S
(mol%) _CO2
(mol%) Flow rate (mmscfd) Sour Gas Stream(503) 2.0 10.0 90.0 10.0 Compressed Mixed Stream (506) 15.0 11.6 88.4 17.0 First MS Concentrate Stream (521) 15.0 30.0 70.0 5.7 First MS permeate stream (522) 2.0 2.5 97.5 11.0 Second MS Concentrate Stream (531) 15.0 90.0 10.0 1.1 Second MS permeate stream (532) 2.0 85.0 15.0 4.5 Tail gas stream (541) 2.0 13.9 86.1 0.2 Concentrated Carbon Dioxide Stream (551) 2.0 0.0 100 9.0 Recovered hydrogen sulfide stream (552) 2.0 12.1 87.9 2.6 MS, membrane phase
^a Areas of 940 and 720 m ² in the first and second membrane stages 520 and 530, respectively; and using a membrane with a theoretical compressive force of 1590 kWe.
^b absolute pressure

Example 2: Two-stage permeate-continuous arrangement with feed to membrane separation unit and amine absorption unit

Simulations were performed using a two-stage permeate-continuous membrane stage arrangement with sour gas fed to the membrane separation unit and amine absorption unit as shown in Figure 6. In this example, the process and system include elements and features similar to those shown in FIGS. 2B and 3C. The membrane separation unit comprised two stages with permeate-continuous, sour gas was introduced into the membrane separation unit and the amine absorption unit. Similar to Example 1, sour natural gas stream 601 having the same composition as sour natural gas stream 501 provided in Example 1 was processed to obtain sweetened natural gas stream 602 and sour gas stream 603. It is treated in the natural gas processing unit 610 by a non-selective acid gas removal process. As in Example 1, sour gas stream 603 contains 90 mol% carbon dioxide, 10 mol% hydrogen sulfide, and negligible amounts of contaminants.

Sour gas stream 603 may be combined with other sour gas streams. In this case, it is combined with the hydrogen sulfide stream 652 recovered from the selective absorption unit 650 to obtain a mixed sour gas stream 604. The mixed sour gas stream (604) is compressed to 15 bar and separated in a first membrane separation stage (620) to obtain a first membrane stage retentate stream (621) and a first membrane stage permeate stream (622). It is combined with the second membrane stage retentate stream 631 to obtain a mixed stream. The first membrane stage retentate stream 621 is sent to a sulfur recovery unit 640 to obtain a sulfur stream 642 and a tail gas stream 641. Here, sulfur recovery unit 640 does not include a dedicated amine absorption unit to treat tail gases from the Claus process, which significantly reduces equipment costs.

The first membrane stage permeate stream 622 is compressed and sent to the second membrane stage 630 to obtain a second membrane stage retentate stream 631 and a second membrane stage permeate stream 632. The second membrane stage permeate stream (632) is combined with the tail gas stream (641) and sent to a selective amine absorption unit (650).

Stream composition: two-stage permeate with sour gas fed to membrane separation unit and selective amine absorption unit - continuous membrane stage arrangement ^a Pressure (bar) ^b _H2S
(mol%) _CO2
(mol%) N ₂
(mol%) Flow rate (mmscfd) Sour Gas Stream(603) 2.0 10.0 90.0 0.0 10.0 Compressed Mixed Stream (609) 15.0 10.0 90.0 0.0 20.4 First MS Concentrate Stream (621) 15.0 90.0 10.0 0.0 1.1 First MS permeate stream (622) 2.0 5.27 94.7 0.0 19.2 Second MS Concentrate Stream (631) 15.0 10.0 90.0 0.0 9.3 Second MS permeate stream (632) 2.0 0.51 99.1 0.0 10.0 Concentrated CO ₂ Stream (651) 2.0 0.01 82.7 17.3 11.0 Recovered H ₂ S Stream (652) 2.0 9.7 90.3 0.0 1.1 MS, membrane phase
^a Areas of 1,907 and 723 m ² in the first and second membrane stages 620 and 630, respectively; and with a theoretical compressor power of 1720 kWe.
^b absolute pressure

Example 3: Comparison of sulfur recovery processes with and without membrane separation

A refinery may have operations that produce sour gas suitable for direct processing in a sulfur recovery unit. In some cases, the concentration of hydrogen sulfide in these streams may be greater than about 90 mol%, with less than about 10 mol% carbon dioxide. This stream can be fed directly to the sulfur recovery unit without treatment to concentrate the hydrogen sulphide. However, carbon dioxide from the recycle stream can build up in the system and reduce the effectiveness of the sulfur recovery unit. An example of such a system is shown in Figure 7A. In Figure 7A, sour gas stream 703 contains 90 mol% hydrogen sulfide and 10 mol% carbon dioxide. The stream also contains very low amounts of contaminants (i.e., less than about 0.01 mol%). 7A, a Claus reactor in which sour gas stream 703 is combined with hydrogen sulfide-enriched stream 742 and then reacted with air from air stream 719 to obtain sulfur stream 722 and tail gas stream 721. Introduced in (720). Tail gas stream 721 is treated in catalytic reactor 730 with hydrogen from hydrogen stream 729 to reduce residual sulfur components to hydrogen sulfide. Off-gas stream 731 contains about 1 to 2 mol% hydrogen sulfide; It also contains both carbon dioxide from the sour gas stream (703) and nitrogen from the air stream (719).

Off-gas stream 731 is sent to selective amine absorption unit 740 to remove hydrogen sulfide. Selective amine absorption unit 740 produces a treated tail-gas stream 741 containing nitrogen and carbon dioxide and a hydrogen sulfide-enriched stream 742 containing hydrogen sulfide and carbon dioxide, where carbon dioxide is the dominant component. Hydrogen sulfide-enriched stream 742 is significantly diluted such that the hydrogen sulfide concentration in mixed sour gas stream 704 is less than 75 mol% (Table 6).

Stream composition: Sulfur recovery process without membrane separation unit Pressure (bar) ^a _H2S
(mol%) _CO2
(mol%) N ₂
(mol%) Flow rate (mmscfd) Sour Gas Stream(703) 2.0 90.0 10.0 0.0 10.0 H ₂ S-concentrated stream (742) 2.0 10.7 89.3 0.0 2.6 Mixed Sour Gas Stream(704) 2.0 73.4 26.4 0.0 12.6 Off-gas stream (731) 2.0 1.2 14.3 84.5 23.0 Treated Tail-Gas Stream (741) 2.0 0.0 4.8 95.2 21.0 ^a absolute pressure

The hydrogen sulfide concentration in the mixed sour gas stream 704 can be increased using the arrangement shown in FIG. 7B. The arrangement shown in FIG. 7B involves compressing the recycle stream and then separating the hydrogen sulfide-enriched stream using a carbon dioxide-selective membrane and membrane separating it to obtain a permeate stream 751 and a retentate stream 752. It includes supplying to 750. Membrane separation stage 750 has a carbon dioxide-selective membrane with a carbon dioxide permeability of 500 gpu and a carbon dioxide-hydrogen sulfide selectivity of 10. Membranes with greater selectivity are generally expected to result in better separation of components, but often at the expense of permeability, which results in larger areas being required.

The process depicted in FIG. 7B is a Shell Claus off-gas treatment (SCOT) process that includes converting hydrogen disulfide in the tail gas to hydrogen sulfide and removing the hydrogen sulfide using methyl diethanolamine (MDEA) selective absorption. It can be used with a Claus plant arranged to have. However, the present disclosure is not limited to this process. Those skilled in the art will also consider other possible arrangements and modifications to achieve similar results.

Concentrate stream 752 has a greater hydrogen sulfide concentration (i.e., 50 mol%) in this configuration than the configuration shown in Figure 7A. This increased hydrogen sulfide concentration in retentate stream 752 also results in a greater hydrogen sulfide concentration (i.e., 87.9 mol%) in mixed sour gas stream 704 (Table 7).

Stream composition: Sulfur recovery process ^a with membrane separation unit Pressure (bar) ^b _H2S
(mol%) _CO2
(mol%) N ₂
(mol%) Flow rate (mmscfd) Sour Gas Stream(703) 2.0 90.0 10.00 0.0 10.0 Mixed Sour Gas Stream(704) 2.0 87.9 12.1 0.0 10.6 Off-gas stream (731) 2.0 1.3 6.0 92.7 21.3 Mixed Off-Gas Stream(732) 2.0 1.55 14.2 84.2 23.4 Treated tail-gas stream (741) 2.0 0.0 95.2 4.8 20.7 H ₂ S-concentrated stream (742) 15.0 13.3 86.7 0.0 2.7 Permeate Stream (751) 2.0 3.8 96.2 0.0 2.1 Concentrate Stream (752) 15.0 50.0 50.0 0.0 0.6 a Using a membrane with ^an area of 192 m ² and a theoretical compressor power of 255 kWe
^b absolute pressure

Example 4: Low-Concentration Hydrogen Sulfide Feed Using a Two-Stage Concentrate-Continuous Membrane Separation Arrangement

A process is provided in this embodiment for treating streams with relatively low concentrations of hydrogen sulfide without a dedicated amine absorption process to treat the tail gas. An example of the above process and system is provided in Figure 8 (Table 8). 8, sour gas stream 803 is prepared to obtain a mixed sour gas stream 805 that is separated in selective amine absorption unit 820 to obtain concentrated carbon dioxide stream 821 and recovered hydrogen sulfide stream 822. 1 combined with the membrane stage permeate stream (832) and tail gas stream (851).

Because the recovered hydrogen sulfide stream 822 is too diluted to be sent directly to the sulfur recovery unit 850, it is sent to a membrane separation unit to concentrate the hydrogen sulfide for the sulfur recovery process. The recovered hydrogen sulfide stream (822) is combined with the second membrane stage permeate stream (841). The combined recovered hydrogen sulfide stream 822 and the second membrane stage permeate stream 841 are introduced into a membrane separation unit comprising two membrane stages with permeate-continuity as shown in FIG. 2C. The first membrane stage retentate stream 831 is sent to a second membrane stage 840 to obtain a second membrane stage retentate 842 and a second membrane stage permeate 841. The second membrane stage permeate is recycled through the membrane separation unit and the second membrane stage retentate is sent to sulfur recovery unit 850.

Sulfur recovery unit 850 includes a Claus unit and a catalytic reactor. This is because the concentration of hydrogen sulfide in the Claus unit is sufficient for conversion but does not include a dedicated selective amine absorption unit to treat the tail gas from the Claus unit.

Stream composition: two-stage permeate-continuous membrane stage arrangement with low-concentration hydrogen sulfide ^a Pressure (bar) ^b H ₂ S (mol%) _CO2
(mol%) N ₂
(mol%) Flow rate (mmscfd) Sour Gas Stream(803) 2.0 2.0 98.0 0.0 20.0 Mixed Sour Gas Stream(805) 2.0 2.5 94.2 3.2 24.5 Recovered H ₂ S Stream (822) 20.0 15.2 84.8 0.0 4.1 First MS permeate stream (832) 2.0 5.6 94.4 0.0 3.6 First MS Concentrate Stream (831) 20.0 70.0 30.0 0.0 0.75 Second MS Concentrate Stream (842) 20.0 90.0 10.0 0.0 0.46 Tail gas stream (851) 2.0 1.9 5.4 91.5 0.86 MS, membrane phase
a Using membranes with an ^area of 264 and 60 m ² and a theoretical compressor power of 488 kWe
^b absolute pressure

Example 6: Two-stage permeate-continuous membrane separation arrangement with feed to membrane separation unit and amine absorption unit

A process comprising a two-stage permeate-continuous membrane separation arrangement with sour gas fed to the membrane separation unit and the amine absorption unit was simulated (Table 9). The process and system are shown in Figure 9 and include similar elements and features as shown in Figures 2B and 3C. In Figure 9, sour gas is compressed and introduced into a membrane separation unit with a two-stage permeate-continuous arrangement similar to that shown in Figure 2b. Sour gas stream 903 has a hydrogen sulfide concentration of about 20 mol% and is nitrogen-free, making it suitable for processing in a membrane separation unit, but the hydrogen sulfide concentration is relatively low and thus less desirable.

The first membrane stage retentate stream (921) is sent to the Claus unit (950). The second membrane stage permeate stream (932) is combined with the recycle stream (971) from the second amine absorption unit (970) and compressed to obtain the first amine unit feed stream (939). First amine unit feed stream 939 is processed in first amine unit 940 to obtain a concentrated carbon dioxide stream 941 and a recovered hydrogen sulfide stream. The amine unit is used to treat the first amine unit feed stream 939 because this stream contains a significant concentration of nitrogen (33.3 mol%) which is problematic for membrane separation processes. The recovered hydrogen sulfide stream is then combined with the first membrane stage concentrate stream (921) to obtain a Claus feed stream (949).

Claus feed stream 949 is introduced into Claus unit 950 with air stream 948 to produce sulfur stream 952 and tail gas stream 951. The tail gas stream 951 is sent to a catalytic reactor 960 with a hydrogen stream 959 to produce an off-gas stream 961 by converting the sulfur dioxide present in the tail gas stream to hydrogen sulfide. The off-gas stream (961) is then sent to a secondary amine absorption unit (970) where it is processed to obtain a nitrogen stream (972) and a recycle stream (971). Recycle stream 971 is suitable for processing in first amine unit 940 because it has a relatively low concentration of hydrogen sulfide (i.e., less than about 20 mol %).

Stream composition: two-stage permeate-continuous membrane stage arrangement with low-concentration hydrogen sulfide ^a Pressure (bar) ^b H ₂ S (mol%) _CO2
(mol%) N ₂
(mol%) O ₂
(mol%) Flow rate (mmscfd) Sour gas stream (903) 2.0 20.0 80.0 ― ― 10.0 First MS permeate stream (922) 2.0 10.2 89.8 ― ― 11.9 First MS Concentrate Stream (921) 20.0 60.0 40.0 ― ― 2.9 Second MS permeate stream (932) 2.0 3.4 95.6 ― ― 7.1 Off-gas stream (961) 2.0 1.5 28.8 66.1 3.6 7.2 Primary amine unit feed stream (939) 20.0 2.4 62.4 33.3 1.8 14.2 Recovered H ₂ S Stream (942) 2.0 28.1 71.9 ― ― 1.2 Claus Feed Stream (949) 2.0 50.5 49.5 ― ― 4.2 Air Stream(948) 2.0 ― ― 79.0 21.0 6.0 MS, membrane phase
^a Using membranes with areas of 810 and 390 m ^2
b absolute pressure

Although the present embodiments have been described in detail, it should be understood that various changes, substitutions, and alterations may be made without departing from the spirit and scope of the disclosure. Accordingly, the scope of the embodiments should be determined by the following claims and their appropriate legal equivalents.

The singular forms “a, an” and “the” include plural referents unless the context clearly dictates otherwise.

“Optional” or “optionally” means that the subsequently described event or circumstance may or may not occur. Descriptions include instances in which an event or situation occurs and instances in which it does not occur.

Ranges may be expressed herein as from about one particular value and/or to about another particular value. It should be understood that when such ranges are expressed, further embodiments range from one specific value and/or to another specific value along with all combinations within the range.

As used herein and in the appended claims, the words “comprise,” “has,” and “include,” and all grammatical variations thereof, each do not exclude additional elements or steps. It is intended to have an open, non-restrictive meaning.

Descriptions may use ordinal numbers (“first,” “second,” “third,” etc.) merely to identify specific components or steps and distinguish them from others described by the same or similar terms. Unless explicitly provided otherwise, the use of ordinal numbers does not indicate relationship, order, quality, rank, or significance; Nor does it define numerical limits.

Claims (22)

A process for recovering sulfur and carbon dioxide from a sour gas stream, comprising:
providing a sour gas stream to a membrane separation unit comprising a membrane, wherein the membrane is a carbon dioxide-selective membrane and wherein the sour gas stream comprises hydrogen sulfide and carbon dioxide;
separating hydrogen sulfide from carbon dioxide in the membrane separation unit to obtain a retentate stream and a permeate stream, wherein the retentate stream comprises hydrogen sulfide and has a concentration of hydrogen sulfide of 80 to 95 mol%; , wherein the permeate stream comprises carbon dioxide;
introducing the concentrate stream into a sulfur recovery unit;
processing the concentrate stream in a sulfur recovery unit to produce a sulfur stream and a tail gas stream, wherein the sulfur stream comprises liquid sulfur;
introducing the permeate stream to an amine absorption unit; and
A process for recovering sulfur and carbon dioxide from a sour gas stream comprising treating the permeate stream in an amine absorption unit to produce a concentrated carbon dioxide stream. delete delete In claim 1,
A process for recovering sulfur and carbon dioxide from a sour gas stream, wherein the membrane has a carbon dioxide-hydrogen sulfide selectivity of at least 10 and a permeance of at least 500 gas permeation units (gpu). In claim 1,
A process for recovering sulfur and carbon dioxide from a sour gas stream, wherein the membrane separation unit comprises a membrane made from a perfluoropolymer. In claim 1,
A process for recovering sulfur and carbon dioxide from a sour gas stream, wherein the membrane separation unit comprises two membrane stages in a retentate-in-series configuration. In claim 1,
A process for recovering sulfur and carbon dioxide from a sour gas stream, wherein the membrane separation unit comprises two membrane stages in a permeate-in-series configuration. A process for recovering sulfur and carbon dioxide from a sour gas stream, said process comprising:
providing a sour gas stream to a selective amine absorption unit, the sour gas stream comprising hydrogen sulfide and carbon dioxide;
separating hydrogen sulfide from carbon dioxide in a selective amine absorption unit to produce a concentrated carbon dioxide stream and a concentrated hydrogen sulfide stream, wherein the enriched carbon dioxide stream comprises carbon dioxide;
introducing the concentrated hydrogen sulfide stream into a membrane separation unit, wherein the concentrated hydrogen sulfide stream comprises hydrogen sulfide and carbon dioxide;
separating hydrogen sulfide from carbon dioxide in the concentrated hydrogen sulfide stream in the membrane separation unit to produce a retentate stream and a permeate stream, wherein the concentration of hydrogen sulfide in the retentate stream is 80 to 95 mol%, and the membrane separation unit comprises a membrane, wherein the membrane is a carbon dioxide-selective membrane;
introducing the concentrate stream into a sulfur recovery unit, wherein the concentrate stream comprises hydrogen sulfide; and
Processing the concentrate stream in a sulfur recovery unit to produce a sulfur stream and a tail gas stream, wherein the sulfur stream comprises liquid sulfur. delete delete In claim 8,
A process for recovering sulfur and carbon dioxide from a sour gas stream, wherein the membrane has a carbon dioxide-hydrogen sulfide selectivity of at least 10 and a permeability of at least 500 gpu. In claim 8,
A process for recovering sulfur and carbon dioxide from a sour gas stream, wherein the membrane separation unit comprises a membrane made from a perfluoropolymer. In claim 8,
A process for recovering sulfur and carbon dioxide from a sour gas stream, wherein the tail gas stream is recycled to a selective amine absorption unit. In claim 8,
A process for recovering sulfur and carbon dioxide from a sour gas stream, wherein the membrane separation unit comprises two membrane stages in a retentate-continuous arrangement. In claim 8,
A process for recovering sulfur and carbon dioxide from a sour gas stream, wherein the membrane separation unit comprises two membrane stages in a permeate-continuous arrangement. a first sour gas stream having a carbon dioxide and hydrogen sulfide concentration greater than 10 mol% and a nitrogen concentration less than 10 mol% and a second sour gas stream having a carbon dioxide and hydrogen sulfide concentration less than 20 mol% or a nitrogen concentration greater than 10 mol%. A process for recovering sulfur and carbon dioxide from two sour gas streams, said process comprising:
introducing the first sour gas stream into a membrane separation unit and separating the first sour gas stream to obtain a retentate stream and a permeate stream, the retentate stream comprising hydrogen sulfide and the permeate stream comprising carbon dioxide; wherein the membrane separation unit comprises a membrane, wherein the membrane is a carbon dioxide-selective membrane;
Introducing the permeate stream and the second sour gas stream to a selective amine absorption unit and using the amine absorption process to obtain a recovered hydrogen sulfide stream and a concentrated carbon dioxide stream, the recovered hydrogen sulfide stream comprising hydrogen sulfide and a concentrated carbon dioxide stream. The carbon dioxide stream includes carbon dioxide;
recycling the recovered hydrogen sulfide stream to a membrane separation unit; and
introducing the concentrate stream into a sulfur recovery unit and processing the concentrate stream using a Claus process to obtain a sulfur stream comprising sulfur, wherein the concentrate stream is introduced into the sulfur recovery unit. A process for recovering sulfur and carbon dioxide from two sour gas streams, wherein the concentrate stream contains 80 to 95 mol% hydrogen sulfide. delete In claim 16,
A process for recovering sulfur and carbon dioxide from two sour gas streams, wherein the membrane separation unit comprises two membrane stages in a retentate-continuous arrangement. In claim 16,
A process for recovering sulfur and carbon dioxide from two sour gas streams, wherein the membrane separation unit comprises two membrane stages in a permeate-continuous arrangement. In claim 16,
A process for recovering sulfur and carbon dioxide from two sour gas streams, wherein the membrane separation unit comprises a membrane made of a perfluoropolymer. In claim 16,
A process for recovering sulfur and carbon dioxide from two sour gas streams, wherein the membrane has a carbon dioxide-hydrogen sulfide selectivity of at least 10 and a permeability of at least 500 gpu. In claim 16,
A process for recovering sulfur and carbon dioxide from two sour gas streams, wherein the second sour gas stream contains 5 to 50 mol% nitrogen.